Side-tracking cement plug

ABSTRACT

Method for altering the trajectory of a borehole by use of a sidetracking plug.

This is a continuation of application Ser. No. 964,979 filed Oct. 22,1992, now abandoned.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates to the use of cement plugs in a well,particularly an oil or gas well, and particularly side tracking plugs.

2. Background of the Invention

Rotary drilling of a borehole is accomplished by rotating a drill stringhaving a drill bit at its lower end. Weight is applied to the drillstring while rotating to create a borehole into the earth. The boreholemay pass through numerous different strata before the borehole reachesthe desired depth. The drill string is usually hollow and sections areadded to the drill string to increase its length as the borehole isdeepened. The trajectory of the borehole is critical to intersecting oiland gas bearing formations. The mechanical variables of the drillingprocess such as the type of bit, rotary speed, amount of weight applied,and effective stiffness of the drill string have significant impact onthe path of the borehole. Additionally, characteristics of the geologicformations traversed by the borehole such as formation dip, formationstrike, hardness, fluid content, type of fluid, porosity, permeability,in-situ stresses, compressive and tensile strength, and chemicalcomposition also influence the trajectory of the borehole.

In many instances the design of the drill string, selection of bit,applied weight and rotary speed can be used to control the trajectory ofthe borehole. However, in some cases, conditions in the drillingoperation may require that a new trajectory be established from a pointin the existing borehole. Reasons for this include loss of directionalcontrol through formation or mechanical variables, failure to locate atarget formation at the initially indicated point in the earth, loss ofor damage to part of the drill string which causes it to become anobstruction within the existing well path or re-entry into an existingwellbore to increase production from other formations.

Regardless of the reason, altering the path of the borehole is oftenaccomplished by spotting a cement plug or whipstock plug at apreselected point in the existing path. The formulation of the cementplug is such that its hardness is greater than the hardness of thesurrounding rock. Hence, the resistance of the cement plug is greaterthan the resistance of the formation rock and the drill bit willpreferentially drill the softer material and establish a new path forthe borehole, referred to in the drilling art as "sidetracking".

Setting cement plugs has several potential problems particularly wherehigh strength and good adhesion to the borehole wall are needed in orderto divert the path of the drill bit into the surrounding formations.First, contamination of the cement slurry with a drilling fluidgenerally alters the setting time and compressive strength of the cementformulation. Most water based drilling fluids increase the setting timerequiring a longer waiting period for the resumption of drillingoperations since compressive strength development is delayed. Oil invertemulsion drilling fluids (oil muds) typically have a high calciumchloride brine internal liquid phase which can significantly reduce thesetting time and strength of the Portland cement. Contact with anybrine, e.g. seawater, in the drilling fluid or in the well will reducethe strength of Portland cement.

Second, contamination of Portland cement with the drilling fluid ishighly probable due to the process used to place the cement plug in theborehole. A successive displacement process is used wherein the cementslurry is pumped down the drill string (or similar work string with aninner diameter substantially smaller than the diameter of the borehole).The slurry is then displaced out the bottom of the drill string into theannulus between the borehole and drill string by pumping a second(displacing) fluid down the drill string. This displacing fluid istypically drilling fluid.

The borehole is filled with drilling fluid and the cement slurry exitingthe bottom of the drill string is traveling at a higher velocity thanthe fluid moving up the much larger annular space. Thus the cementslurry is "jetted" into the drilling fluid as its flow direction changes180 degrees. Any chemical incompatibility between the drilling fluid andcement slurry may produce a gelled mass that inhibits effectivedisplacement of the drilling fluid by the Portland cement slurry whichcan result in contamination of the entire cement volume.

Spacers are often used ahead of the Portland cement slurry to preventcontamination of the cement with the drilling fluid. These spacers aresimilar in composition to the drilling fluid. Clay and/or polymericthickeners are used to viscosity the base fluid (usually water) in orderto suspend weighting agents such as barites, hematites, or ilmenite.Emulsions of oil and water may also be used to provide viscosity forsolids suspension. Often, surfactants and/or other solvents may beincorporated into the spacer to improve compatibility with the drillingfluid. Although more chemically compatible with the cement, spacercontamination of the cement slurry can occur and the effect on cementcompressive strength is often similar to the effect of drilling fluidcontamination.

Third, the cement must adhere to the borehole walls to prevent downwardmovement of the plug when weight is applied during the drillingoperation. This adhesion is typically referred to as the shear bondstrength of the cement. Coatings on the surfaces of the formation canreduce the shear bond of the cement. The borehole wall is typicallycoated with a drilling fluid filter cake which was deposited when theformation was penetrated by the initial drilling operation. Thisdrilling fluid filter cake has low strength and may be sheared off theborehole wall by downward movement of the cement plug during drilling.Drilling may be aggravated by the thickness of the filter cake and anybypassed drilling fluid left in sections of the annulus. Also, anycoating of the spacer along the borehole wall may reduce the shear bondstrength between the borehole wall and the cement plug.

The density of many materials used for plugs is greater than thedrilling fluid density. The primary reason for this is highercompressive strength and greater drilling resistance. For Portlandcement plugs, lower water to cement ratios are required to providegreater strength. Greater strength often is used to offset the potentialstrength reduction due to contamination by the drilling fluid. Thedisadvantage of high density formulations is the possibility of the plugfalling through the drilling fluid below the interval where the plug isdesired. The density differential between the drilling fluid andPortland cement increases the probability that an unstable interfacewill result between the cement and drilling fluid. If the interfacebetween fluids is unstable, cement and drilling fluid can mix causing apoor quality plug.

Accordingly, the present invention is directed to overcoming the abovenoted problems with Portland cement in the art, and in particular toproblems experienced with effective "sidetracking" in oil and gas wells.

SUMMARY OF THE INVENTION

It is the primary purpose of the present invention to provide a methodfor altering the trajectory or path of a borehole with a diverting andplugging agent.

The purpose of this invention is achieved through a method for alteringthe path or trajectory of a borehole through placement of a plug whichhas greater drilling resistance than formations surrounding theborehole, comprising:

preparing a cementitious slurry comprising:

(a) a cementitious component selected from blast furnace slag and aproton acceptor metal compound and

(b) an activator wherein, when said cementitious component is said blastfurnace slag, said activator is optionally an alkaline agent, and whensaid cementitious component is said metal compound, said activator is aphosphorus acid or one of a polymer component of the formula: ##STR1##and wherein R is H or a 1-10 carbon atom alkyl radical and the ratio ofm to n is within the range of 0:1 to 100:1 and

(c) a water source selected from water, brine, seawater, water basedrilling fluid, and water emulsion drilling fluid;

circulating the cementitious slurry to a preselected location in theborehole, the cementitious slurry being in direct contact during andafter placement with drilling fluid in the borehole; and

allowing the cementitious slurry to solidify in situ to form a plug inthe wellbore.

Other purposes, distinctions over the art, advantages and features ofthe invention will be apparent to one skilled in the art upon review ofthe following.

DESCRIPTION OF PREFERRED EMBODIMENTS

The following preferred embodiments of the invention explain theprinciples of the invention.

The present invention provides a unique method devised to provide"sidetracking" for vertical, deviated, and horizontal wells. Theinvention centers around the solidification of non-conventional cementplugs preparatory to effecting sidetracking. As described supra,"sidetracking" is altering the path of a borehole by spotting a cementplug at a preselected point in the existing path.

The present invention provides an improved process for plugging asection of an existing borehole with a non-conventional cement, thecement being resistant to drilling fluid contamination, having betteradhesion to the filter cake along the borehole wall and being morecompatible with the drilling fluid in the wellbore. The non-conventionalcementitious slurry of this invention is more rheologically andchemically compatible with the drilling fluid than is a cementconventionally applied in sidetracking. Thus, the invention encompassesembodiments in which no spacers are used ahead of the cementitiousslurry to prevent commingling with the drilling fluid. In suchembodiments, the non-conventional cementitious slurry is placed indirect contact with the drilling fluid, eliminating the need forproblem-causing chemical spacers which are preferred for placement ofPortland cement plugs, as discussed supra.

The present invention is especially useful when tools, drill string,etc. are lost in the hole during drilling; sidetracking the hole aroundsuch non-retrievable fish may be the only solution. As known to the art,a whipstock can be used to guide the drill bit in the desired direction.

Drilling of the borehole is preferably conducted with a universal fluidwhich is a drilling fluid containing a minor quantity of anon-conventional cementitious component. This results in a settablefilter cake being deposited on the borehole wall. The settable filtercake furnishes an excellent means for bonding the sidetracking plug tothe borehole in order to effectively seal the thief zone.

Cementing of the well is preferably conducted by adding a major amountof the non-conventional cementitious component to the universal fluid.This results in a cement which readily bonds to the settable filtercake. Of course it is manifest that drilling and cementing may beconducted with conventional fluids known to the art which work well withthe non-conventional cement plugs of this invention.

In this description the term `cementitious material` means either anhydraulic material which on contact with water and/or activators hardensor sets into a solidified composition or a component which, on contactwith a reactive second component, sets or hardens into a solidifiedcomposition. Thus, broadly it can be viewed as a material which canchemically combine to form a cement. A slurry of the cementitiousmaterial and the component or components which cause it to harden isreferred to herein as a cementitious slurry. The term `pipe` means acasing or liner.

Drilling Fluids

The initial drilling fluid or mud can be either a conventional drillingfluid, i.e., one not containing a cementitious material, or it can beone already containing a cementitious material in a relatively smallamount. The drilling fluid can be either a water-based fluid or anoil-based fluid. The term `water-based fluid` is intended to encompassboth fresh water muds, salt water containing muds, whether made fromseawater or brine, and other muds having water as the continuous phaseincluding oil-in-water emulsions. In any event drilling fluid willalways contain at least one additive such as viscosifiers, thinners,dissolved salts, solids from the drilled formations, solid weightingagents to increase the fluid density, formation stabilizers to inhibitdeleterious interaction between the drilling fluid and geologicformations, and additives to improve the lubricity of the drillingfluid.

It is generally preferred that the water-based drilling fluids use watercontaining dissolved salts, particularly sodium chloride. In theseinstances, 0.1 to saturation, preferably 0.5 to 20, more preferably 3 to10 wt % sodium chloride may be used. One suitable source is to useseawater or a brine solution simulating seawater. Particularly in theembodiment using slag, the strength of the resulting cement is actuallyenhanced which is contrary to what would be expected in view of theintolerance of Portland cement to brine. Various salts, preferablyorganic salts, are suitable for use in the drilling fluid used in thisinvention in addition to, or instead of NaCl, including, but not limitedto, NaBr, KCl, CaCl₂, NaNO₃, NaCHO₂, NaC₂ H₃ O₂, KC₂ H₄ O₂, and KCHO₂among which sodium chloride is preferred, as noted above. The term`oil-based fluids` is meant to cover fluids having oil as the continuousphase, including low water content oil-base mud and invert oil-emulsionmud.

A typical mud formulation to which cementitious material may be added toform drilling fluid is as follows: 10-20 wt % salt (70,000-140,000mg/1), 8-10 lbs/bbl bentonite, 4-6 lbs/bbl carboxymethylated starch(fluid loss preventor), sold under the trade name "BIOLOSE" by Milpark,0.5-1 lbs/bbl partially hydrolyzed polyacrylamide (PHPA) which is ashale stabilizer, sold under the trade name "NEWDRIL" by Milpark, 1-1.25lbs/bbl CMC sold under the trade name "MILPAC" by Milpark, 30-70 lbs/bbldrill solids, and 0-250 lbs/bbl barite.

The term `universal fluid` is used herein to designate thosecompositions containing cementitious material, which compositions aresuitable for use as a drilling fluid, and which compositions thereafter,for the purpose of practicing this invention, have additionalcementitious material and/or activators such as accelerators (orreactive second components) added to give a cementitious slurry.

Thus, with the universal fluid embodiment of this invention, the purposeof one aspect of the invention is achieved through a method for drillingand cementing a well comprising preparing a universal fluid by mixing adrilling fluid and a cementitious material; drilling a borehole with theuniversal fluid and laying down a settable filter cake on the walls ofthe borehole during drilling of the well; diluting the drilling fluid;adding additional cementitious material and/or accelerators (or reactivesecond components) and introducing the thus-formed cementitious slurryinto the wellbore and into an annulus between the wellbore and a casingwhere it hardens and sets up forming a good bond with the filter cakewhich filter cake, with time, actually hardens itself because of thepresence of cementitious material therein. This hardening is facilitatedby any accelerators which may be present in the cementitious slurry andwhich migrate by diffusion and/or filtration into the filter cake.

Non-Conventional Cements

The cementitious component can be any one or more of: conventionalhydraulic cement, natural or artificial pozzolan, or the metal compoundused to produce an ionomer or to produce a phosphorus salt. Thepreferred cementitious material is one selected from the groupconsisting of blast furnace slag, a metal compound which is a protonacceptor component used to produce the ionomer and a metal compoundwhich is a proton acceptor component used to produce the phosphorussalt. By `blast furnace slag` is meant the hydraulic refuse from themelting of metals or reduction of ores in a furnace as disclosed in Haleand Cowan, U.S. Pat. No. 5,058,679 (Oct. 22, 1991), the disclosure ofwhich is hereby incorporated by reference. By `phosphorus salt` is meanta phosphonate, a phosphate or a polyphosphate as is described in detailhereinafter.

The preferred blast furnace slag used in this invention is a high glasscontent slag produced by quickly quenching a molten stream of slag at atemperature of between 1400° C. and 1600° C. through intimate contactwith large volumes of water. Quenching converts the stream into amaterial in a glassy state having hydraulic properties. At this stage itis generally a granular material that can be easily ground to thedesired degree of fineness. Silicon dioxides, aluminum oxides, ironoxides, calcium oxide, magnesium oxide, sodium oxide, potassium oxide,and sulphur are some of the chemical components in slags. Preferably,the blast furnace slag used in this invention has a particle size suchthat it exhibits a Blaine specific surface area between 500 cm² /g and15,000 cm² /g and more preferably, between 3,000 cm² /g and 15,000 cm²/g, even more preferably, between 4,000 cm² /g and 9,000 cm² mostpreferably between 4,000 cm² /g and 9,000 cm² /g. An available blastfurnace slag which fulfills these requirements is marketed under thetrade name "NEWCEM" by the Blue Circle Cement Company. This slag isobtained from the Bethlehem Steel Corporation blast furnace at SparrowsPoint, Md.

A usual blast furnace slag composition range in weight percent is: SiO₂,30-40; Al₂ O₃, 8-18; CaO, 35-50; MgO, 0-15; iron oxides, 0-1; S, 0-2 andmanganese oxides, 0-2. A typical specific example is: SiO₂, 36.4; Al₂O₃, 16.0; CaO, 43.3; MgO, 3.5; iron oxides, 0.3; S, 0.5; and MnO₂ O₃<0.1.

Blast furnace slag having relatively small particle size is frequentlydesirable because of the greater strength it imparts in many instancesto a final cement. Characterized in terms of particle size the term"fine" can be used to describe particles in the range of 4,000 to 7,000cm² /g Blaine specific surface area. Corresponding to 16 to 31 micronsin size; "microfine" can be used to describe those particles in the7,000 to 10,000 cm² /g Blaine specific surface area range thatcorrespond to particles of 5.5-16 microns in size and "ultrafine" can beused to describe particles over 10,000 cm² /g Blaine specific surfacearea that correspond to particles 5.5 microns and smaller in size.

However, it is very time consuming to grind blast furnace slag to theseparticles sizes. It is not possible to grind blast furnace slag in amanner where particles are entirely once size. Thus, any grindingoperation will give a polydispersed particle size distribution. A plotof particle size versus percent of particles having that size would thusgive a curve showing the particle size distribution.

In accordance with a preferred embodiment of this invention a blastfurnace slag having a polydispersed particle size distributionexhibiting at least two nodes on a plot of particle size versus percentof particles in that size is utilized. It has been found that if only aportion of the particles are in the ultrafine category, the remaining,indeed the majority, of the slag can be ground more coarsely and stillgive essentially the same result as is obtained from the more expensivegrinding of all of the blast furnace slag to an ultrafine state. Thus, agrinding process which will give at least 5% of its particles fallingwithin a size range of 1.9 to 5.5 microns offers a particular advantagein economy and effectiveness. More preferably, 6 to 25 wt % would fallwithin the 1.9 to 5.5 micron range. The most straightforward way ofobtaining such a composition is simply to grind a minor portion of theblast furnace slag to an ultrafine condition and mix the resultingpowder with slag ground under less severe conditions. Even with the lesssevere conditions there would be some particles within the fine,microfine or ultrafine range. Thus, only a minority, i.e., as little as4 wt % of the slag, would need to be ground to the ultrafine particlesize. Generally, 5 to 20 wt %, more preferably 5 to 8 wt % can be groundto the ultrafine particle size and the remainder ground in a normal waythus giving particles generally in a size range of greater than 11microns, the majority being in the 11 to 31 micron range.

By ionomer is meant organometal compositions having a metal attached toor interlocking (crosslinking) a polymer chain. Suitable polymercomponents of such ionomers can be represented by the formula ##STR2##and wherein R is H or a 1-10 carbon atom alkyl radical. The ratio of mto n is generally within the range of 0:1 to 100:1, preferably 0.1:1 to10:1.

The polymers generally have a ratio of functional groups to polymerchain carbons within the range of 1:2 to 1:10, preferably about 1:3.Thus, if m and n are 1, R is H and A is carboxylate, there would be aratio of carboxylic carbons (1) to polymer chain carbons (4) of 1:4. Thepolymer can also be a polycarboxylic acid polymer. One such polymer isthat made from partially hydrolyzed polyacrylamide. The hydrolysis canvary from 1% up to 100% and preferably from 10% to 50%, most preferablyfrom 25% to 40%. The molecular weight of the polymers can vary widely solong as the polymers are either water-soluble or water-dispersable. Theweight average molecular weights can range from 1000 to 1,000,000 butpreferably will be in the range of 1,000 to 250,000, most preferably10,000 to 100,000. Carboxylate polymer with a low ratio of COOH:C withinthe range of 1:3 to 2:5 are preferred. Especially preferred is acarboxylic acid polymer having a ratio of carboxylic carbons to polymerchain carbons (including carbons of pendant chains) of about 1:3 and amolecular weight within the range of 10,000 to 100,000. Partiallyhydrolyzed polyacrylamide polymers in the range of 5,000-15,000,000molecular weight are suitable. The copolymers will generally have from2-99, preferably 5-80, more preferably 10-60 mole percentacid-containing units.

The poly(carboxylic acid) component can be any water soluble or waterdispersable carboxylic acid polymer which will form ionomers. Ionomerforming polymers are well known in the art. Suitable polymers includepoly(acrylic acid) poly(methacrylic acid), poly(ethacrylic acid),poly(fumaric acid), poly(maleic acid), poly(itaconic acid) andcopolymers such as ethylene/acrylic acid copolymer andethylenemethacrylic acid copolymer. The copolymers are generally randomcopolymers. An example of phosphonic acid polymers is poly(vinylphosphonic acid) which is made from vinyl phosphonic acid, ##STR3##Suitable copolymers containing vinyl phosphonic acid include vinylphosphonic acidacrylic acid copolymer as well as copolymers with otherunsaturated monomers, with or without a functional group.

In some instances, it is preferred to use water dispersable, as opposedto water soluble, polymers. Ideally, in such instances the melting pointof the polymer should be higher than the placement temperature(circulating temperature) in the wellbore during the "cementing"operation and lower than the maximum, static temperature of thesurrounding formations. It is desirable for the polymer to melt andreact after placement as the temperature in the wellbore increases fromthe circulating temperature to the static temperature of the surroundingformations.

The ionomers suitable for use in this invention are the water-insolublereaction product of a proton acceptor metal compound which serves as thecementitious component and a carboxylic, sulfonic, or phosphonic acidpolymer component. The metal compound generally is a metal oxide such asCaO, MgO or ZnO. The preferred metal oxides are magnesium oxide and zincoxide, and most preferably, magnesium oxide. The applicable metal oxidesare generally fired at temperatures above 1,000° F. for several hours toreduce chemical activity prior to grinding to final particle size foruse in reacting with the acid component.

In instances where it is desired that the metal compound component addweight to the drilling fluid, the metal compound is preferably awater-insoluble metal compound with a specific gravity of at least 3.0,preferably 3.5. By `insoluble` is meant that less than 0.01 parts byweight dissolve in 100 parts by weight of cold (room temperature) water.

The particle size of the metal compound component can vary widely.Generally, it will be within the range such that the powder exhibits asurface area within the range of 500 cm² /g to 30,000 cm² /g, preferably1,500 cm² /g to 25,000 cm² /g to preferably 2,000 cm² /g to 20,000cm.sup. /g.

The amount of polymer utilized will vary widely depending upon thecarboxylic acid content of the polymer; broadly, 10 to 200, preferably10 to 100, most preferably 10 to 80wt %, based on the weight of metalcompound, can be present. With the polymers having a low ratio of m ton, a smaller amount is required because of the higher functional groupcontent of the polymer. Conversely, with the high ratio of m to n, anamount of polymer toward the higher end of the ranges is preferred.Polymers with ester groups can be used to delay or retard the setting ofthe ionomer cement.

Phosphates and phosphonates, referred to herein as phosphorus salts,used in accordance with this invention also are produced from atwo-component composition, the first component of which is a metalcompound identical in scope to that used in the ionomers as describedhereinabove so long as the resulting phosphorus salt is insoluble inwater. Most preferred are MgO and ZnO.

The second component is a phosphonic or phosphoric acid, preferably apolyphosphoric acid. The term `phosphoric acid` is meant to encompassboth linear and cyclic polyphosphoric acids. These second componentacids are referred to herein as phosphorus acids. Linear phosphoricacids can be depicted by the general formula H_(n+2) P_(n) O_(3n+1)where n is 1 to 100, preferably 2 to 50, more preferably, 2 to 20.Examples include di-(pyro)phosphoric acid, tri-(tripoly)phosphoric acid,tetra-phosphoric acid and higher molecular weight polyphosphoric acidsas well as phosphoric acid. Mixtures of acids, including thosetraditionally referred to as meta phosphoric acid, are particularlysuitable for use in this invention.

The formation of one phosphate cement using a metal oxide as the metalcompound can be depicted as follows: ##STR4## where: X is usually 4; and

MO=metal oxide which is amphoteric or is a proton acceptor.

The phosphorus acid component is used in a stoichiometric amount or lesssince an excess of acid should generally be avoided. From 1 to 10 oreven 1 to 50 mole percent less than a stoichiometric amount is suitable.Generally, a stoichiometric amount will be between 10 and 100 wt % basedon the weight of the metal compound.

With the ionomers, and the phosphorus salts when made with a polyvalentmetal compound, a crosslinked network structure exists as a result ofthe addition of the second component, thus giving a very strong solidcement.

Because of the mass provided by the metal compound component of theionomer or the polyphosphorus salt, these cementitious materials aregenerally actually heavier than most slag or Portland cement materials.In the embodiments using these cementitious materials this high densityprovides significant advantages in certain utilities. For one thing, asmaller amount of the material can be used and still achieve a final mudand ultimately cement of a desired density. Secondly, because of thehigh density, it is possible to operate without weighting agents such asbarium sulfate or barite. They offer a further advantage in that they donot set up until the second component is added.

The metal compound of the ionomer or phosphorus salt can be used as thesole cementitious material or can be used in admixture with siliceoushydraulic materials such as the blast furnace slag or Portland cement.In one embodiment an hydraulic component such as slag can be used togive the metal ion component of the ionomer or phosphate to give, ineffect, a mixture formed in situ.

Preferably, when the ionomer or phosphorus salt is utilized, the metalcompound is added first and thereafter at such time as it is desired forthe cement to be activated to set, the other component is added. In thecase of the universal fluids, a portion of the total metal compound canbe added to the drilling fluid, the remainder being added after dilutionwhen the cementitious slurry is being formed. Boric acid, borate saltsand aluminates such as sodium aluminate can be used to retard or delaythe setting of the phosphate cement as desired. Amount of 1-100% byweight of the retarder, based on the weight of the phosphorus acid, areeffective.

The sequence for the universal fluid embodiment of this invention is toprepare the drilling fluid containing a portion of the total slag ormetal compound to be utilized, carry out the drilling operation, dilutethe fluid, add the remainder of the slag or metal compound, andthereafter add the activator or acid components and utilize the cementfor its intended purpose such as cementing a casing.

In accordance with the invention that utilizes universal fluid, thefluid itself becomes a part of the final cement and thus, this portionof the drilling fluid does not need to be disposed of.

In all embodiments of the invention, additional cement can be made andused, in accordance with this invention, for remedial cementing.

The ionomer embodiments of this invention are of particular value forfilling and sealing the annulus between a borehole wall and a casing, orbetween casings, particularly where some degree of ductility and/ortensile strength is desired. The ionomer has good adhesive properties tothe borehole wall and casing and has greater elasticity than is obtainedwith siliceous hydraulic materials such as Portland cement. Thus, suchcements are resistant to cracking under conditions of cyclic loading asare frequently encountered in a wellbore. For similar reasons theionomer embodiment of the invention is beneficial in cementing linersand tieback casing strings which may otherwise leak due to changes inpressure and temperature in the well during production operations.Another area where the ductility of the ionomer cement is of specialvalue is in slim hole wells where the annulus is smaller. Still yetanother area where this ductility is important is in extended reachdrilling. The term `extended reach` is intended to cover horizontaldrilling and any other well drilling operations which are off-vertical asufficient amount to cause the casing to be displaced by gravity towardone side of the borehole.

As noted hereinabove the initial drilling fluid can be either aconventional drilling fluid or it can be a universal fluid which alreadyhas cementitious material therein.

Dilution

In all embodiments, the amount of dilution can vary widely depending onthe desired application. Generally, the fluid will be diluted with from5 to 200 by volume, preferably 5 to 100% by volume, more preferably 5 to50% by volume of liquid (water in the case of a water-based fluid) basedon the volume of initial drilling fluid. In one particularly preferredembodiment, the dilution is such that on addition of the cementitiouscomponent (or in the case of the universal fluid addition of theremaining cementitious component) the final density will be within therange of 30% less to 70% more than the original density, preferablywithin the range of 15% less to 25% more, most preferably, essentiallythe same, i.e., varying by no more than ±5 wt %. This is particularlyvaluable in an operation where there is a narrow pressure window betweenthe pressure needed to prevent blowout and the pressure which wouldrupture or fracture the formation through which drilling has takenplace.

The dilution fluid can be the same or different from that used to makethe drilling fluid in the first place. In the case of brine-containingfluids the dilution fluid will generally be brine also. This is ofparticular benefit in offshore drilling operations where fresh water isnot readily available but brine is since seawater is a desirable brine.

Thus, as noted above, a significant improvement in the operatingprocedure is provided in accordance with this invention. This is becausethe density of the drilling fluid is frequently tailored to thecharacteristics of the formation through which the wellbore is beingdrilled. Thus, the density is chosen in the first place to be sufficientto avoid inflow into the wellbore because of formation pressure but isfurther chosen to be insufficient to rupture or fracture the boreholewall and force the fluid out into the formation. By utilizing thedilution and thereafter addition of the cementitious component (or inthe case of universal fluid, the remainder of the cementitiouscomponent) the cementitious slurry can likewise have a density tailoredto the particular operation. In addition, this avoids undue thickeningof the drilling fluid as would occur, particularly with some hydrauliccomponents, without the dilution and thus the rheological properties ofthe cementitious slurry and the drilling fluid can both be tailored foroptimum performance.

The invention (dilution of a drilling fluid and thereafter addingcementitious material to produce a cementitious slurry) offers specialadvantages with certain cementitious components in addition to thegeneral benefits such as reduced equipment needs. With Portland cementit reduces the extraordinary viscosity increase that adding such anhydraulic material to a drilling fluid would give. With slag,organometals and polyphosphates there is the advantage that thecementitious component has a drilling fluid function. With the ionomersand polyphosphates there is the further general advantage that unlimitedtime can elapse between the drilling and cementing operations with noloss of properties of either because these materials do not begin to setuntil the second component is added.

The dilution can be carried out in either of two ways. First, a vesselcontaining drilling fluid can simply be isolated and the desired amountof water or other diluent added thereto. In a preferred embodiment,however, the drilling fluid is passed to a mixing zone as a flowingstream and the dilution fluid added "on the fly" to the flowing stream.Thereafter the additional blast furnace slag is added. This avoidshighly viscous cementitious slurry compositions and allows all of thepumping to be done with piping and pumps associated with the well rigwithout the need for pumps designed for pumping cement. This is ofparticular value in the areas to which this invention is of specialutility, offshore drilling rigs where the transportation of additionalpumping equipment is particularly inconvenient. Thus, it is possible totailor the final density of the cementitious slurry, if desired, to avalue within the range of 30% less to 70% more than the original densityof the drilling fluid, preferably within the range of 15% less to 50%more, most preferably essentially the same, i.e., varying by no morethan ±5 weight percent.

Mixed metal hydroxides can be used in the drilling fluid to impartthixotropic properties. The mixed metal hydroxides provide better solidssuspension. This, in combination with the settable filter cake providedin the technique of this invention, greatly enhances the cementing in arestricted annulus. The mixed metal hydroxides are particularlyeffective in muds containing clay such as sodium bentonite. Preferredsystems thickened in this way contain from 1-20 lbs/bbl of clay such asbentonite, preferably 2 to 15 lbs/bbl, most preferably 7 to 12 lbs/bbl.The mixed metal hydroxides are generally present in an amount within therange of 0.1 to 2 lbs/bbl of total drilling fluid, preferably 0.1 to 1.5lbs/bbl, most preferably 0.7 to 1.2 lbs/bbl. Mixed metal hydroxides areknown in the art and are trivalent metal hydroxide-containingcompositions such as MgAl(OH)₄.7 Cl₀.3. They conform essentially to theformula

    Li.sub.m D.sub.d T(OH).sub.(m+2d+3+na) A'.sub.a n

where

M represents the number of Li ions present; the said amount being in therange of zero to about 1;

D represents divalent metals ions; with

d representing the amount of D ions in the range of zero to about 4;

T represents trivalent metal ions;

A' represents monovalent or polyvalent anions of valence -n, other thanOH⁻, with a being the amount of A' anions; and

where (m+2d+3na) is equal to or greater than 3. A more detaileddescription can be found in Burba, U.S. Pat. No. 4,664,843 (May 12,1987). The mixed metal hydroxides in the drilling fluid, in combinationwith blast furnace slag, tend to set to a cement having considerablestrength in a comparatively short time, i.e., about one-half hour attemperatures as low as 100° F. This can be a major asset in someapplications. In such instances, a thinner such as a lignosulfate ispreferably added before adding slag. However, one of the advantages ofthis invention is that it reduces or eliminates the need for additivesto control free water or solids suspension. The activator or activatorscan be added either with any other ingredients that are added before theadditional blast furnace slag, with the additional blast furnace slag,or after the addition of the additional blast furnace slag.

In some instances, it may be desirable to use a material which functionsas a retarder along with the activator because of the need for othereffects brought about by the retarder. For instance, a chromiumlignosulfonate may be used as a thinner along with the activator eventhough it also functions as a retarder.

Other suitable thinners include chrome-free lignosulfonate, lignite,sulfonated lignite, sulfonated styrene maleic-anhydride, sulfomethylatedhumic acid, naphthalene sulfonate, a blend of polyacrylate andpolymethacrylate, an acrylamideacrylic acid copolymer, a phenolsulfonate, a naphthalene sulfonate, dodecylbenzene sulfonate, andmixtures thereof.

In one embodiment the drilling fluid consists essentially of slag andseawater and is pumped exclusively using the piping and pumps associatedwith the drilling rig without the need for any pumps designed forpumping cement.

In the case of hydraulic materials, particularly the more preferredhydraulic material, blast furnace slag, the amount of hydraulic materialpresent in the universal fluid is generally within the range of 1 to 100lbs/bbl of final drilling fluid, preferably 10 to 80 lbs/bbl, mostpreferably 20 to 50 lbs/bbl. In the case of the organometals (ionomers)or phosphorus salts the amount of metal compound initially present inuniversal fluid can also vary widely. Generally, 1 to 500 lbs/bbl,preferably 50 to 300 lbs/bbl, most preferably 100 to 250 lbs/bbl of themetal compound are used.

The total amount of cementitious material in the cementitious slurrywill typically range from about 20 lbs/bbl to about 600 lbs/bbl,preferably 100 lbs/bbl to 500 lbs/bbl, most preferably 150 lbs/bbl to350 lbs/bbl. This can be adjusted to give the desired density as notedhereinabove.

Reference herein to additives encompasses both the specialized additivesnecessary for this invention such as the carboxylic acid polymer in thecase of the ionomer or the polyphosphoric acid in the case of thepolyphosphate as well as conventional additives.

Conventional Drilling Fluid Additives

Suitable fluid loss additives found in drilling fluids include bentoniteclay, carboxymethylated starches, starches, carboxymethyl cellulose,synthetic resins such as "POLYDRILL" by SKW Chemicals, sulfonatedlignite, lignites, lignin, or tannin compounds. Weight materials includebarite, calcium carbonate, hematite and MgO, for example. Shalestabilizers that are used in drilling fluids include hydrolyzedpolyacrylonitrile, partially hydrolyzed polyacrylamide, salts includingNaCl, KCl, sodium or potassium formate, sodium or potassium acetate,polyethers and polycyclic and/or polyalcohols. Viscosifying additivescan be used such as biopolymers, starches, attapulgite and sepiolite.Additives are also used to reduce torque. Suitable thinners such aschrome and chrome free lignosulfonates, sulfonated styrenemaleic-anhydride and polyacrylate may also be used depending upon themud type and mud weight. Lubricating additives include nonionicdetergents and oil (diesel, mineral oil, vegetable oil, synthetic oil),for instance. Alkalinity control can be obtained with KOH, NaOH or CaO,for instance. In addition, other additives such as corrosion inhibitors,nut hulls etc. may be found in a typical drilling fluid. Of course,drill solids including such minerals as quartz and clay minerals(smectite, illite, chlorite, kaolinite, etc.) may be found in a typicalmud.

It is particularly desirable in accordance with a further embodiment ofthis invention to utilize silica to increase the temperature resistanceof the final blast furnace slag cement. The use of blast furnace slag asthe hydraulic component, in itself, allows greater latitude in thetemperature which can be tolerated, because the blast furnace slag isinherently less thermally sensitive than other known hydrauliccomponents such as Portland cement and thus can be hardened over a widerrange of temperatures without resort to additives. This is of particularadvantage where there is a substantial temperature gradient from the topto the bottom of a borehole section to be cemented. However, with theaddition of silica, further temperature resistance may be imparted tothe cement after it is set. Thus, with blast furnace slag and silica atemperature resistant cement is possible and with other cementitiouscomponents the temperature range can be extended through the usedsilica. Suitable silicas include crystalline silicas such as alphaquartz.

Universal Fluids

In another embodiment of this invention, most or all of the componentsof the drilling fluid are chosen such that they have a function in thecementitious material also. The following Table illustrates theuniqueness of such formulations.

                                      TABLE A                                     __________________________________________________________________________            Function                                                                      Drilling Fluid  Cementitious Slurry                                   Additive                                                                              Primary  Secondary                                                                            Primary                                                                              Secondary                                      __________________________________________________________________________    Synthetic                                                                             Fluid loss      Fluid loss                                                                             Retarder                                     polymer.sup.1                                                                         control         control                                               Starch.sup.2                                                                          Fluid loss                                                                             Viscosity                                                                            Fluid loss                                                                             Retarder                                             control         control                                               Biopolymer.sup.3                                                                      Viscosity       Viscosity                                                                              Retarder                                     Silicate                                                                              Viscosity                                                                              Shale  Accelerator                                                                            --                                                            stabilizer                                                   Carbohydrate                                                                          Deflocculant                                                                           --     Retarder Defloccu-                                    polymer.sup.4                    lant                                         Barite.sup.5                                                                          Density  --     Density  Solids                                                               concentration                                         Bentonite.sup.6                                                                       Fluid loss                                                                             --     Fluid loss                                                                             Solids                                               control         control  concentr.                                    Clay/Quartz                                                                           --       --     Solids   --                                           dust                    concentration                                         Slag.sup.8                                                                            Cuttings --     Cementitious                                                                           Solids                                               stabilizer      concentration                                         Lime.sup.9                                                                            Cuttings/                                                                              Alkalinity                                                                           Accelerator                                                                            Solids                                               Wellbore        concentration                                                 stabilizer                                                            PECP.sup.10                                                                           Shale    Fluid loss                                                                           Retarder Rheologi-                                            stabilizer               cal                                                                           Control                                      NaCl    Shale    --     --       --                                                   stabilizer                                                            __________________________________________________________________________     .sup.1 Polydrill, A synthetic polymer manufactured by SKW Chemicals Inc.      under trade name Polydrill, for instance                                      .sup.2 Starch made by Milpark Inc. under the trade name "PERMALOSE", for      instance.                                                                     .sup.3 A biopolymer made by Kelco Oil Field Group, Inc., under the trade      name "BIOZAN" for instance.                                                   .sup.4 Watersoluble carbohydrate polymer manufactured by Grain Processing     Co. under trade name "MORREX".                                                .sup.5 Barite is BaSO.sub.4, a drilling fluid weighting agent.                .sup.6 Bentonite is clay or colloidal clay thickening agent.                  .sup.7 Clay/quartz solid dust manufactured by MilWhite Corp. under the        trade name "REVDUST", for instance.                                           .sup.8 Blast furnace slag manufactured by Blue Circle Cement Co. under th     trade name "NEWCEM" is suitable.                                              .sup.9 CaO                                                                    .sup.10 Polycyclicpolyetherpolyol                                        

The material in the above Table A labeled PECP is of specialsignificance in connection with this invention. This refers to apolyhydric alcohol most preferably a polycyclicpolyetherpolyol. Ageneral chemical composition formula representative of one class ofthese materials is as follows: ##STR5## where x≧1 and y≧0.

A more complete description of these polycyclicpolyetherpolyols is foundin the Hale and Cowan patent, U.S. Pat. No. 5,058,679 (Oct.22, 1991),referred to hereinabove, the disclosure of which is incorporated hereinby reference.

Universal drilling fluids which utilize blast furnace slag can besubsequently activated to cause the drilling fluid to developcompressive strength with time.

Suitable activators include sodium silicate, sodium fluoride, sodiumsilicofluoride, magnesium silicofluoride, magnesium hydroxide, magnesiumoxide, zinc silicofluoride, zinc oxide, zinc carbonate, titaniumcarbonate, sodium carbonate, potassium sulfate, potassium nitrate,potassium nitrite, potassium carbonate, sodium hydroxide, potassiumhydroxide, copper sulfate, lithium hydroxide, lithium carbonate, calciumoxide, calcium sulfate, calcium nitrate, calcium nitrite, calciumhydroxide, sodium sulfate and mixtures thereof. A mixture of causticsoda (sodium hydroxide) and soda ash (sodium carbonate) is preferredbecause of the effectiveness and ready availability. When mixtures ofalkaline agents such as caustic soda and soda ash are used the ratio canvary rather widely since each will function as an accelerator alone.Preferably, about 1 to 20 lbs/bbl of caustic soda, more preferably 2 to6 lbs/bbl of caustic soda are used in conjunction with from 2 to 50lbs/bbl, preferably 2 to 20 lbs/bbl of soda ash. The references to"lbs/bbl" means pounds per barrel of final cementitious slurry.

A combination of sodium hydroxide and sodium carbonate is preferred. Inaddition, blast furnace slag can be added between the use of thismaterial as a drilling fluid and its use as a cement. The additionalslag can be the activator, especially if heat is imparted to theoperation. Each component is an important ingredient for both thedrilling fluid and the cement. The PECP is particularly significant incombination with slag since it acts as a retarder and thus providessignificant drilling fluid functions in general and specific drillingfunctions relative to the slag component as well as significant cementfunctions. PECP also reduces the friction coefficient of muds on casingand filter cake, and pullout forces required to release stuck pipe aredramatically reduced with PECP in the drilling fluid. In addition, PECPacts as a rheological modifier as a result of its absorptive tendencieson to polymers and clays.

The unique advantage of universal fluids is that wellbore stabilization,fluid-loss control, and cuttings transport can be realized essentiallythe same as with conventional drilling fluid systems. However, with thesimple presence of activators in the subsequent cementitious slurry, theresulting mud-slag system will develop strength. Thus, for instance,

(1) drilling fluid filter cake deposited while drilling over permeablezones can be converted into an effective sealant by diffusion ofactivators from the mud-slag column; and

(2), whole mud that has not been removed from washed-out sections of thehole during displacement will harden with time and, therefore, providean effective sealant and lateral support to the casing.

In areas such as slim hole drilling, the ionomer universal fluid givesthe process benefit of avoiding the removal of an incompatible drillingmud and the product benefit of being resistant to deflection when set.

In the case of the universal fluids, the amount of cementitious materialcan vary considerably and also can vary depending upon whether thecementitious component is a siliceous material, an organometal, or apolyphosphate.

Process and apparatus used to drill and cement are well known. Oneexample can briefly illustrate typical practice as follows. A well isdrilled using a hollow drill string having a drill bit with at least oneorifice communicating between the inside of the hollow drill string andthe outside and located at the lower end of the drill string, thusproducing a wellbore. During this drilling, a drilling fluid iscirculated down the inside of the drill string and out of the orifice atthe lower end thereof. When the drilling is complete, the drill stringis withdrawn from the wellbore. A first section of well casing,generally having a float shoe with an upper sealing surface, is insertedinto the wellbore. Additional sections of casing are generally attachedsequentially to the first section and the first section is insertedfurther into the wellbore. In accordance with one embodiment of thisinvention, additional drilling fluid, containing additives necessary toform a cementitious slurry, is pumped down the casing. This may befacilitated by inserting a bottom plug into the casing string, thebottom plug having a longitudinal passage and a rupturable diaphragm atthe top, so that it is forced down the casing by he cementitious slurry.Thereafter, a top or second plug can be inserted into the casing stringabove the column of cementitious slurry, the diaphragm of the first plugruptured, and the slurry forced up into an annulus between the outsideof the casing and the inside of the borehole where, with time, ithardens.

In accordance with another embodiment of this invention, the use ofthese conventional plugs for separating the cementitious slurry from thedrilling fluid is generally not necessary. In this embodiment the drillstring is simply removed, a casing inserted, and the cementitious slurrycirculated into the borehole and up the annulus. This can abe done bydirect fluid contact between the displacement fluid and the cementitiousslurry thus eliminating the need for a loading collar or wiper plug.

In yet another related embodiment of this invention, universal fluid isutilized in a drilling operation and thereafter additional cementitiousmaterial and/or additives, or the second component of a two-componentsystem, is gradually added so as to gradually transition the circulatingmaterial from a drilling fluid to a cementitious slurry.

Filter Cake Setting

In yet another embodiment of this invention the drilling process iscarried as described hereinabove with a universal fluid to produce aborehole through a plurality of strata thus laying down a filter cake.Prior to the cementing operation the activator or reactive secondcomponent is passed into contact with the filter cake, for instance bycirculating the activator or reactive second component down the drillstring and up the annulus between the drill string and the filter cake.This can be accomplished by circulating a separate fluid containing theactivator or reactive second component or by adding an activator orreactive second component to the drilling fluid. Alternatively, thedrill string is removed and the casing inserted and the activator orreactive second component circulated down the casing and up the annulus.As used herein `down` as it relates to a drill string or casing, meansin a direction toward the farthest reach of the borehole even though inrare instances the borehole can be disposed in a horizontal position.Similarly, `up` means back toward the beginning of the borehole.Preferably, the circulation is carried out by using the drill string,this being the benefit of this embodiment of the invention whereby thefilter cake can be `set` to shut off gas zones, water loss, or to shutoff lost circulation in order to keep drilling without having to removethe drill string and set another string of casing. This can also be usedto stabilize zones which may be easily washed-out (salt zones whereinthe salt is soluble in water, for instance) or other unstable zones.After the drilling is complete the drilling fluid is then diluted, thedrill string removed, and the cementing carried out as describedhereinabove.

Conventional spacers may be used in the above described sequence. Also,any left over fluid having activators therein may be displaced out ofthe borehole by the next fluid and/or a spacer fluid and stored forsubsequent use or disposal.

In this embodiment where the filter cake is "set", the activator can beany of the alkaline activators referred to hereinabove such as a mixtureof sodium hydroxide and sodium carbonate when the universal fluidcontains slag, or a polymer with a functional group such as a carboxy asdescribed hereinabove wherein the universal fluid contains a metalcompound proton acceptor, or the phosphoric (or polyphosphoric) orphosphonic acid component of a phosphate or phosphonate when theuniversal fluid contains a metal compound proton acceptor.

In another embodiment of this invention, the drilling is done using adrilling fluid containing a metal compound to lay down a filter cakewhich is preferably set by circulating a polymer as described to producean ionomer or by circulating a phosphorus acid to produce a phosphatesalt. Thereafter, the cementing is done with a cementitious slurrycomprising blast furnace slag and an accelerator. Also, the use of blastfurnace slag as described above for the metal compound source of anionomer or phosphate salt can be used in this embodiment as well. Thus,ionomers or phosphorus salts can be formed as filter cake followed bycementing with blast furnace slag.

Surfactants, alcohols, or blends thereof may be used in the drillingfluids of this invention to improve bonding.

Bonding Surfactants

The surfactants may be anionic, amphoteric, cationic, nonionic or blendsthereof, e.g., nonionics with anionic or cationic surfactants.

The following surfactants, classes of surfactants, and mixtures ofsurfactants are particularly useful in the present invention:

1. Alkanol amides (nonionic): ##STR6## where R=a carbon chain (alkylgroup) of 8-20 carbons (usually 10-18); H₁ and/or H2 may be replaced byan alkanol such as ethanol or isopropanol. One or both of the H's may bereplaced.

Examples: lauric monoisopropanol amide, lauric diethanol amide, coconutdiethanol amide. ALKAMIDE 2106® by Alkaril Chemicals, Ltd. is a coconutdiethanol amide suitable for this application.

2. Ethoxylated alkyl aryl sulfonate:

Examples: nonyl phenol sulfonate with 8 moles ethylene oxide, andN-decyl benzene sulfonate with 6 moles ethylene oxide.

3. Amine oxides (nonionic): ##STR7## where R=alkyl carbon chains from 1to 20 carbons, usually one chain is 10 to 18 carbons. Alkyl groups canhave hydroxyl or amido functional groups in their chain.

Examples: bis(2-hydroxyethyl) coco amine oxide, bis(2-hydroxyethyl)laurel amine oxide, laurel dimethyl amine oxide, coco amidopropyldimethyl amine oxide, cetyl dimethyl amine oxide, myristyl dimethylamine oxide.

4. Betaines and Betaine Derivatives ##STR8## where R₁ =alkyl chainlength between 3 and 20 carbons, R₂ =alkyl chain length between 1 and 4carbons. Amide functional groups may be incorporated into the R₁ alkylchain.

Examples: coco amido propyl betaine (R₂ =propyl group 3 carbons), laurelbetaine (R₁ =laurel group of 12 carbons, no R₂), coco betaine (R₁ =cocogroup of 12 -14 carbons, no R₂), oleyl betaine (R₁ --oleyl group of 18carbons, no R₂), myristic betaine (R₁ =myristyl group of 14 carbons, noR₂), oleamido propyl betaine, isostearamido propyl betaine, laurelsulfobetaine.

5. Ethoxylated Alcohols (nonionic): Ethoxylated simple alcohols withlinear or branched chains having between 8 and 20 carbons with 3 to 20mole of ethylene oxide groups; 6-14 moles of ethylene oxide are typical.

Examples: C₉ -C₁₁ linear alcohol with 8 moles ethylene oxide, C₁₄ -C₁₅linear alcohol with 13 moles ethylene oxide, C₁₂ -C₁₅ linear alcoholwith 9 moles ethylene oxide.

6. Sulfates and Sulfonates of Ethoxylated Alcohols (anionic): The sameranges apply as in No. 5 supra except ethylene oxide moles may varybetween 2 and 14.

Examples: C₁₂ -C₁₃ linear alcohol sulfate or sulfonate with 3 molesethylene oxide, C₁₂ -C₁₅ linear alcohol sulfate or sulfonate with 3moles ethylene oxide.

7. Ethoxylated Alkyl Phenols (nonionic): Alkyl chains of 8 to 20carbons, usually between 4 and 14 carbons and more preferred to be 8 or9 carbons, with 4-20 moles of ethylene oxide, usually between 7 and 20moles and more preferred to 8-12 moles.

Examples: Nonylphenol with 9 moles ethylene oxide, octylphenol with 8moles ethylene oxide.

8. Sulfates or Sulfonates of Ethoxylated Alkyl Phenols (and their salts)(anionic)

Examples: Nonyl phenol sulfate or sulfonate with 9 moles ethylene oxide;octyl phenol sulfate or sulfonate with 8 moles ethylene oxide.

9. Fluorocrabon-based Surfactants (nonionic, amphoteric, anionic): Thesemust be water-soluble forms. Fluorocarbon esters such as 3M Company's"FC-740" are oil soluble and not appropriate for this use. 3M Company's"FC-100", "FC-129", "FC-170C" are commercially available examples offluorocarbon-based surfactants used in the invention.

Examples: Fluoro-octyl sulfonate or sulfate, perfluorated quaternaryammonium oxide, and fluorinated C₉ -C₁₁ alcohols with 7 moles ethyleneoxide.

10. Phosphate Derivatives of Ethoxylated Alcohols:

Examples: C₁₄ -C₁₆ linear alcohols phosphate with 8 moles ethyleneoxide; phosphated nonylphenol with 10 moles ethylene oxide.

11. Quaternary Ammonium Chloride (cationic): Dimethyl dicoco ammoniumchloride, cetyl dimethyl benzyl ammonium chloride, cetyl dimethylammonium chloride.

12. Sulfates or Sulfonates of Alcohols (and their salts)(Anionic):Sulfated simple alcohols with carbon chains of 8-20, usually between 10and 16 and most common 10-12.

Examples: Sodium lauryl sulfate or sulfonate, potassium lauryl sulfateor sulfonate, magnesium lauryl sulfate or sulfonate, sodium n-decylsulfate or sulfonate, triethanol amine laurel sulfate or sulfonate,sodium 2-ethylhexyl sulfate or sulfonate.

13. Condensation Products of Ethylene Oxide and Propylene Glycol(nonionic):

Examples: Propoxylated C₉ -C₁₄ alcohols with 6 moles ethylene oxide.

The surfactants or mixtures of surfactants should be soluble in thecementitious slurry and not precipitate or otherwise degrade under theaction of the ions in the cementitious slurry (e.g., resistant tocalcium and other electrolytes) and the temperature and pressureconditions occurring during the placement and curing of the cement.

Especially preferred are nonylphenol ethoxylates, coco amido betaine,blends of N-alkyl coco trimethyl ammonium chloride andbis(2-hydroxyethyl) cocoamide oxide, blends of ethoxylatedtrimethylnonanol and perfluoro quaternary ammonium oxide, C₁₂ -C₁₅linear alcohol ethoxylate sulfate, C₉ -C₁₁ linear alcohol ethoxylatesulfates, sodium lauryl sulfate, and ethoxy alcohol sulfates.

The concentration of surfactant in the water phase used to prepare theslurry will generally be from about 0.1 to about 5% by weight, and morepreferably from about 0.2 to about 3% by weight; excellent results havebeen obtained with concentrations between about 1.17 and about 2.33% byvolume.

Alcohols

The invention is very effective for solidification of drilling fluidscontaining polyhydric alcohols. The following alcohols may be used aloneor in blends with the preceding surfactants. The polyalcohol ingredientsof drilling fluids containing polyalcohols are preferably acyclicpolyols having at least two carbon atoms and 2 hydroxyl groups but nomore than 18 carbon atoms and 13 hydroxyl groups. Preferably, thepolyols of the invention have at least 2 carbon atoms and 2 hydroxylgroups, but no more than 9 carbon atoms and 7 hydroxyl groups.

Nonlimiting examples of such polyols include (carbons chains may bestraight or branched), ethylene glycol, diethylene glycol,1,2-propanediol, 1,3-propanediol (propylene glycol), neopentyl glycol,pentaerythritol, 1,6-hexanediol, glycerol, telomers of glycerol such asdiglycerols, triglycerols, tetraglycerols, pentaglycerols, andhexaglycerols, mixtures of glycerol and telomers of glycerol such asdiglycerol and triglycerols, mixtures of telomers of glycerol,polyethylene glycols, polypropylene glycols, ethylenepropylene glycol,polyethylenepropylene glycols, ethylene-propylene glycol copolymers andethylenebutylene glycol copolymers, 1,5,6,9-decanetetrol,1,1,4,4-cyclohexanetetramethanol, 1,2,4,5-cyclohexanetetramethanol,1,4-cyclohexanedimethanol, 1,3-cyclopentanedimethanol,1,2,4,7-heptanetetrol, 1,2,3,5-heptanetetrol, 1,5,8-nonanetriol,1,5,9-nonanetriol, 1,3,5,9-nonanetetrol, 1,3,5-heptanetriol,2,4,6-heptanetriol, 4,4-dimethyl-l,2,3-pentanetriol,1,1,3-cyclohexanetrimethanol, 1,3,4-cycloheptanetriol,1,1-cyclopropanediol, 1,2-cyclopropanediol, 1,2,3-cyclopropanetriol,1,1-cyclopropanedimethanol, 1,2-cyclopropanedimethanol,1,2,3-cyclopropanedimethanol, 1,1-cyclobutanediol, 1,2-cyclobutanediol,1,3-cyclobutanediol, 1,2-cyclobutanedimethanol, 1,2,3-cyclobutanetriol,1,2,4-cyclobutanetriol, 1,2,3,4-cyclobutanetetrol,1,3-dimethyl1,2,3,4-cyclobutanetetrol, 1-hydroxycyclobutanemethanol,3-methyl2,2-butanediol, 1,2-pentanediol, 1,3-pentanediol,1,4-pentanediol, 2,3-pentanediol, 2,4-pentanediol, 1,2,3-pentanetriol,1,2,4-pentanetriol, 2,3,4-pentanetriol, 1,1-cyclopentanediol,1,2-cyclopentanediol, 1,3-cyclopentanediol, 1,2,3-cyclopentanetriol,1,2-hexanediol, 1,3-hexanediol, 1,2,3-hexanetriol, 1,2,4-hexanetriol,1,2,3,4-hexanetetrol, 1,1-cyclohexanediol, 1,2-cyclohexanediol,1,4-cyclohexanediol, 1,2,4-cyclohexanetriol, 1,2,5-cyclohexanetriol,1,2,3,4-cyclohexanetetrol, 1,2,3,5-cyclohexanetetrol, sorbitol,mannitol.

More preferred alcohols are cyclicetherpolyols having at least 6 carbonatoms, at least 2 hydroxyl groups, and at least 2 ether linkages. Evenmore preferred are cyclicetherpolyols having at least 15 carbon atoms, 5ether linkages, and at least 2 hydroxyl groups, or at least 15 carbonatoms, at least 7 ether linkages, and at least 3 hydroxyl groups. Mostpreferred are cyclicetherpolyols having at least 18 carbon atoms, atleast 6 hydroxyl groups, and at least 6 ether linkages. Molecularstructures with significantly larger molecular weights than the aboveminimums have been found to be advantageous. Among thecyclicetherpolyols, monocyclicdietherdiols are preferred andpolycyclicpolyetherpolyols (referred to hereinabove as PECP) are mostpreferred. "Poly" is used to mean two or more.

The alcohols or mixtures of alcohols useful in this invention should besoluble in the drilling fluid of this invention at the temperature andpressure conditions occurring in the wellbore or can be solubilized asdescribed infra. Additionally, the alcohols or mixtures of alcoholsshould not precipitate or otherwise degrade under the actions of theions in the drilling fluid (e.g., resistant to calcium and electrolytes)and the temperature and pressure conditions occurring during drilling.The alcohols may also be soluble at the ambient temperature and pressureconditions on the surface during the preparation of the drilling fluidof this invention. Some of the higher molecular weight alcohols may bevery viscous liquids, or solids or have low solubility at thetemperature conditions at the surface under which the drilling fluid isprepared. In these cases, the alcohols may be diluted with a suitablesolvent which is soluble in the drilling fluid at the temperatureconditions of drilling fluid preparation at the surface. Such suitablesolvents may act to both lower viscosity and to increase solubility ofthe higher molecular weight alcohol for addition to the drilling fluidon the surface. Such solvents may be polyols of lower molecular weight,other alcohols such as methanol, ethanol, propanol, or isopropanol,water or mixtures of solvents and water.

The concentration of alcohol in the water phase when used in thepreparation of the drilling fluid of this invention will generally be atleast about 2% by weight and preferably from about 2 to about 30% byweight based on the water phase and more preferable from about 5 toabout 15% by weight; excellent results have been obtained withconcentrations between about 10 and about 20% by weight. Preferably atleast about 1% w of the alcohol is cyclicetherpolyol or acyclic polyol,based on the total weight of the alcohol.

EXAMPLE 1

Setting cement plugs has several potential problems particularly wherehigh strength and good adhesion to the borehole wall are needed in orderto divert the path of the drill bit into the surrounding formations.First, contamination of the cement slurry with a drilling fluidgenerally alters the setting time and compressive strength of the cementformulation. Table 1 lists the effects of several drilling fluids on thecement.

                  TABLE 1                                                         ______________________________________                                        Effect of Drilling Fluid Contamination on Portland                            Cement Thickening Time                                                        Drilling    Cement:Drilling Fluid                                                                         Thickening Time                                   Fluid Type  Volumetric Ratio                                                                              Hours                                             ______________________________________                                        Test Temperature: 172° F.                                              Oil external                                                                              100:0           4.38                                              emulsion - with                                                                           95:5            3.65                                              30% (bw) calcium                                                                          75:25           1.98                                              chloride brine as                                                                         50:50           1.8                                               internal phase                                                                Test Temperature: 150° F.                                              Water base  100:0           4.23                                              Lignosulfonate                                                                            95:5            5.66                                                          75:25            6.5+                                                         50:50           8+                                                ______________________________________                                    

The effects of different drilling fluids on compressive strength ofcement are shown in Table 2.

                  TABLE 2                                                         ______________________________________                                        Effect of Drilling Fluid Contamination on                                     Compressive Strength of Portland Cement                                       Drilling    Cement:Drilling Fluid                                                                        24 Hr Compressive                                  Fluid Type  Volumetric Ratio                                                                             Strength, psi                                      ______________________________________                                        Test Temperature: 250° F.                                              Oil external                                                                              100:0          2514                                               emulsion - with                                                                           90:10          2230                                               30% (bw) calcium                                                                          75:25           660                                               chloride brine as                                                             internal phase                                                                Test Temperature: 175° F.                                              Water base  100:0          3275                                               Lignosulfonate                                                                            95:5           2670                                                           75:25          1680                                                           50:50          did not set                                        ______________________________________                                    

Spacers are often used ahead of the cement slurry to preventcontamination of the cement with the drilling fluid. These spacers aresimilar in composition to the drilling fluid.

Table 3 shows the effect of different types of spacer contamination onthickening time. Table 4 shows the effect of different types of spacercontamination on compressive strength.

                  TABLE 3                                                         ______________________________________                                        Effect of Spacer Fluid Contamination on                                       Portland Cement Thickening Time                                               Test Temperature: 172° F.                                                                             Thickening                                     Spacer Fluid    Cement:Spacer Fluid                                                                          Time                                           Description     Volumetric Ratio                                                                             Hours                                          ______________________________________                                        Water base with 100:0          4.38                                           bentonite as    95:5           5+                                             primary viscosifier                                                                           75:25          5+                                                             50:50          5+                                             Water base with 100:0          4.38                                           silicate gel as 95:5           4.22                                           primary viscosifier                                                                           75:25          4.75                                                           50:50          5.03                                           Oil external emulsion                                                                         100:0          4.38                                           with 5% KC1 water as                                                                          95:5           4.1                                            internal phase  75:25          4.63                                                           50:50          5.97                                           Oil external emulsion                                                                         100:0          4.38                                           with fresh water as                                                                           95:5           4.47                                           internal phase  75:25          5+                                                             50:50          5+                                             Water base with sodium                                                                        100:0          4.38                                           silicate and carboxy                                                                          95:5           2.47                                           methyl cellulose polymer                                                                      75:25          2.18                                           as primary viscosifiers                                                                       50:50          2.75                                           Water base with 100:0          4.38                                           bentonite and cellulose                                                                       95:5           4.31                                           derivative polymers                                                                           75:25          5+                                             as primary viscosifiers                                                                       50:50          5+                                             Water external emulsion                                                                       100:0          4.38                                           with diesel oil as                                                                            95:5           5+                                             internal phase  75:25          5+                                                             50:50          5+                                             ______________________________________                                    

                  TABLE 4                                                         ______________________________________                                        Effect of Spacer Fluid Contamination                                          on Portland Cement Thickening Time                                            Test Temperature: 250° F.                                                                            24 hr                                           Spacer Fluid   Cement:Spacer Fluid                                                                          Compressive                                     Description    Volumetric Ratio                                                                             Strength, psi                                   ______________________________________                                        Water base with                                                                              100:0          2514                                            bentonite as   95:5           2531                                            primary viscosifier                                                                          75:25          1308                                            Water base with                                                                              100:0          2514                                            silicate gel as                                                                              95:5           2283                                            primary viscosifier                                                                          75:25          1263                                            Oil external emulsion                                                                        100:0          2514                                            with 5% KC1 water as                                                                         95:5           2549                                            internal phase 75:25          1342                                            Oil external emulsion                                                                        100:0          2514                                            with fresh water as                                                                          95:5           1699                                            internal phase 75:25           693                                            Water base with sodium                                                                       100:0          2514                                            silicate and carboxy                                                                         95:5           1330                                            methyl cellulose polymer                                                                     75:25          1042                                            as primary viscosifiers                                                       Water base with                                                                              100:0          2514                                            bentonite and cellulose                                                                      95:5           1690                                            derivative polymers                                                                          75:25           795                                            as primary viscosifiers                                                       Water external emulsion                                                                      100:0          2514                                            with diesel oil as                                                                           95:5           1803                                            internal phase 75:25          did not set                                     ______________________________________                                    

Table 5 contains shear bond data showing the effect of drilling fluid orspacer coatings on the shear bond strength between cement and a cleansteel surface.

                  TABLE 5                                                         ______________________________________                                        Effect of Drilling Fluid or Spacer Coating                                    on Shear Bond Between Portland Cement and a Steel Surface                     Coating Material Shear Bond Strength                                          on Surface of Steel Rod                                                                        psi                                                          ______________________________________                                        None - Clean steel surface                                                                     170                                                          Water base drilling fluid                                                                      55                                                           Water base spacer fluid                                                                        80                                                           Oil base drilling fluid                                                                         5                                                           Oil base spacer fluid                                                                          25                                                           ______________________________________                                    

The density of many materials used for sidetracking plugs is greaterthan the drilling fluid density. The primary reason for this is highercompressive strength and greater drilling resistance. For cement plugs,lower water to cement ratios are required to provide greater strength.Greater strength often is used to offset the potential strengthreduction due to contamination by the drilling fluid. The disadvantageof high density formulations is the possibility of the plug fallingthrough the drilling fluid below the interval where the plug is desired.

EXAMPLE 2 Use of Drilling Fluid-Blast Furnace Slag Plug

Using a drilling fluid-blast furnace slag mixture, a casing shoe was runin a well, and then 80 to 120 feet of drilling fluid-blast furnace slagmixture was left inside the bottom of the casing; no float/landingcollar or wiper plug was run. After the drilling fluid-blast furnaceslag mixture set up in 6 to 12 hours, the casing was satisfactorilypressure tested against the drilling fluid-blast furnace slag plug whichhad set up in the bottom of the casing. A PDC bit was used to drill upto the drilling fluid-blast furnace slag mixture, and then proceed aheadwith drilling the next hole interval.

EXAMPLE 3 Base Mud: Fresh water mud containing bentonite, chromelignosulfonate, and low viscosity polyanionic cellulose.

300 lbs of hard burned magnesium oxide, under the trade name of "MAGCHEM10 CR" by Martin Marietta Magnesia Specialties was added to weight thebase mud up to 12.6 lbs/gal. Varying amounts of a polyacrylic acidsolution were added to solidify the mud. The polyacrylic acid had anaverage molecular weight of about 20,000 and is sold by PolySciences,Inc. The solution contained about 40 wt % polyacrylic acid. The resultsare described in the following Table.

    ______________________________________                                        Amount of Polyacrylic                                                                        Resulting                                                                              Description of                                        Acid Added, % by                                                                             Density  the resulting                                         volume of the mud                                                                            lbs/gal  solid                                                 ______________________________________                                         0             12.6     Did Not Set                                           25             11.9     Set, resilient                                                                good adhesion to surfaces                                                     40 psi after 4 hrs                                    50             11.5     Set, resilient                                                                good adhesion to surfaces                                                     40 psi after 4 hrs                                    100            10.9     Set, highly pliable                                                           good adhesion to surfaces                                                     10 psi after 4 hrs                                    ______________________________________                                    

This Example shows that solutions of functional group-containingpolymers can be used as diluents while also converting the drillingfluid into a solid.

EXAMPLE 4 Base Mud: Fresh water mud containing bentonite, chromelignosulfonate, and low viscosity polyanionic cellulose.

300 lbs of hard burned zinc oxide, prepared in the laboratory by heatinganalytical grade zinc oxide at 1350 C. for 8 hours, cooling and grindingto pass through a 325 mesh screen, was added to weight the base mud upto 13.5 lbs/gal. Varying amounts of a polyacrylic acid solution wereadded to solidify the mud. The polyacrylic acid had an average molecularweight of about 50,000 and is sold by PolySciences, Inc. The solutioncontained about 25 wt % polyacrylic acid. The results are described inthe following Table.

    ______________________________________                                        Amount of Polyacrylic                                                                          Resulting                                                                              Description of                                      Acid Added, % by Density  the resulting                                       volume of the mud                                                                              lb/gal   solid                                               ______________________________________                                         0               13.5     Did Not Set                                         100              11.3     Set, ductile                                                                  310 psi after 4 hrs                                 ______________________________________                                    

EXAMPLE 5

Base Mud: Fresh water mud containing bentonite, chrome lignosulfonate,and low viscosity polyanionic cellulose.

300 lbs of hard burned magnesium oxide, under the trade name of "MAGCHEM10 CR" by Martin Marietta Magnesia Specialties was added to weight thebase mud up to 12.6 lbs/gal. Varying amounts of ethylene/acrylic acidcopolymers were added by weight of the magnesium oxide. The copolymersused were "ACLYN" 540, 580, and 5120 sold by Allied Signal, Inc. Thesecopolymers have low molecular weights and varying amounts of acrylicacid incorporated into the polymer. AC 540 has the lowest acrylic acidcontent and AC 5120 has the highest acrylic acid content.

Each mixture was heated to a temperature above the melting point of thecoplymer and held at that temperature for 24 hours. The average meltingpoint temperature for each of these coplymers was about 100° C. After 24hours the samples were cooled and extracted from the molds. Each had setto form a cohesive solid having compressive strengths between 50 and 700psi. All samples were ductile and good adhesion to metal surfaces.

EXAMPLE 6 Base Mud: Fresh water mud containing bentonite, chromelignosulfonate, and low viscosity polyanionic cellulose.

350 lbs of blast furnace slag sold under the trade name of "NEWCEM" byBlue Circle Cement Company was added to weight the mud to lbs/gal. Anequal volume amount of a polyacrylic acid solution were added tosolidify the mud. The polyacrylic acid had an average molecular weightof about 50,000 and is sold by PolySciences, Inc. The solution containedabout 25 wt % polyacrylic acid. The results are described in thefollowing Table.

    ______________________________________                                        Amount of Polyacrylic                                                                          Resulting                                                                              Description of                                      Added, % by volume                                                                             Density  the resulting                                       of the mud       lbs/gal  solid                                               ______________________________________                                         0               12.6     Did Not Set                                         100              10.9     Set, ductile                                                                  130 psi after 4 hrs                                 ______________________________________                                    

EXAMPLE 7 Base Mud: Fresh water mud containing bentonite, chromelignosulfonate, and low viscosity polyanionic cellulose.

300 lbs of hard burned magnesium oxide, under the trade name of "MAGCHEM10 CR" by Martin Marietta Magnesia Specialties was added to weight thebase mud up to 12.6 lbs/gal. Varying amounts of an ammoniumpolyphosphate solution were added to solidify the mud. The ammoniumpolyphosphate solution used is "POLY-N" sold by Arcadian Corporation andcontains about 50 wt % ammonium polyphosphate. The results are describedin the following table.

    ______________________________________                                        Amount of Poly-N Resulting                                                                              Description of                                      Added, % by volume                                                                             Density  the resulting                                       of the mud       lbs/gal  solid                                               ______________________________________                                         0               12.6     Did Not Set                                         25               12.4     Set, resilient                                                                50 psi after 4 hrs                                  50               12.3     Set, resilient                                                                40 psi after 4 hrs                                  100              12.2     Set, resilient                                                                30 psi after 4 hrs                                  ______________________________________                                    

This example shows that solutions of polyphosphates can be used asdiluents while also converting the drilling fluid into a solid.

EXAMPLE 8 Base Mud: Fresh water mud containing bentonite, chromelignosulfonate, and low viscosity polyanionic cellulose.

300 lbs of hard burned magnesium oxide, under the trade name of "MAGCHEM10 CR" by Martin Marietta Magnesia Specialties was added to weight thebase mud up to 12.6 lbs/gal. Varying amounts of a monoammonium phosphatewere added to solidify the mud. The results are described in thefollowing Table.

    ______________________________________                                        Amount of MAP    Resulting                                                                              Description of                                      Added, % by wt of MgO                                                                          Density  the resulting                                       of the mud       lbs/gal  solid                                               ______________________________________                                         0               12.6     Did Not Set                                         25               12.6     Set, resilient                                                                50 psi after 4 hrs                                  50               12.7     Set, resilient                                                                250 psi after 2 hrs                                 100              12.85    Set, hard                                                                     510 psi after 2 hrs                                 ______________________________________                                    

What is claimed:
 1. A method for altering the path or trajectory of aborehole through placement of a plug which has greater drillingresistance than formations surrounding the borehole,comprising:preparing a cementitious slurry comprisinga proton acceptormetal compound and a polymer component of the formula: ##STR9## whereinA is ##STR10## or a mixture of ##STR11## and wherein R is H or a 1-10carbon atom alkyl radical and the ratio of m to n is within the range of0:1 to 100:1 and a water source selected from water, brine, seawater,water base drilling fluid, and water emulsion drilling fluid;circulating the cementitious slurry to a preselected location in theborehole, the cementitious slurry being in direct contact during andafter placement with drilling fluid in the borehole; allowing thecementitious slurry to solidify in situ to form a plug in the wellbore;and altering the trajectory or path of the borehole by preferentiallydrilling the wellbore around the plug, the plug being harder than thewellbore.
 2. A method for altering the path or trajectory of a boreholethrough placement of a plug which has greater drilling resistance thanformations surrounding the borehole, comprising:combining constituentscomprising water, clay and blast furnace slag to produce a drillingfluid; thereafter utilizing said drilling fluid in a well drillingoperation to form a borehole; introducing additional water to at least aportion of said drilling fluid; introducing additional blast furnaceslag and an activator to said drilling fluid to produce a cementitiousslurry; circulating the cementitious slurry to a preselected location inthe borehole, the cementitious slurry being in direct contact during andafter placement with drilling fluid in the borehole; allowing thecementitious slurry to solidify in situ to form a plug in the wellbore;and altering the trajectory or path of the wellbore by preferentiallydrilling the wellbore around the plug, the plug being harder than thewellbore.
 3. The method of claim 2 wherein the dilution is such that onaddition of the first blast furnace slag, the density will be within therange of 30% less to 70% more than the original density.